IR 05000259/1998003
| ML18039A413 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 06/16/1998 |
| From: | NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML18039A412 | List: |
| References | |
| 50-259-98-03, 50-259-98-3, 50-260-98-03, 50-260-98-3, 50-296-98-03, 50-296-98-3, GL-89-01, GL-89-1, NUDOCS 9807070245 | |
| Download: ML18039A413 (71) | |
Text
'.S.
NUCLEAR REGULATORY COMMISSION
REGION II
Docket Nos:
License Nos:
50-259.
50-260 '0-296 DPR-33 'PR-52.
DPR-68 Report Nos:
50-259/98-03 '0-260/98-03.
50-296/98-03
. Licensee:
Tennessee Valley Authority Facility:
Browns Ferry Nuclear Plant. Units 1.
Z.
8 3 Location:
Dates:
Corner of Shaw and Browns Ferry Roads Athens, AL 35611 April 12, 1998
- Hay 23.
1998 Inspectors:
Accompanying Personnel:
Approved by:
L. Wert. Senior Resident Inspector J. Starefos, Resident Inspector E. DiPaolo, Resident Inspector E. Girard, Reactor Inspector (Section El)
E. Testa, Reactor Inspector (Sections Rl, R2.
R7.
and RB)
D. Thompson, Safeguards Inspector (Section Sl)
H. Holbrook, NRC Contractor H. 0. Christensen, Chief Reactor Projects Branch
Division of Reactor Projects
'7807070245 9806i6 PDR ADOCK 05000259
PDR ENCLOSURE
EXECUTIVE SUMMARY Browns Ferry Nuclear Plant. Units 1, 2.
3 NRC Inspection Report 50-259/98-03.
50-260/98-03, 50-296/98-03 This integrated inspection included aspects of licensee operations'ngineering, maintenance, and plant support.
The report covers a six-week period of resident inspection and inspection of Radiological Controls by a Region II Division of Reactor Safety Inspector.
Additionally. The report includes inspection of motor operated valve program (Generic Letter 89-01)
implementation.
~oerations During a Unit 3 midcycle outage, the licensee successfully identified leaking fuel assemblies.
Strong reactivity controls were administered for control rod manipulations during the subsequent startup (Section 01.1).
The Unit 1 operator and AUOs demonstrated good coordination, communications and self checking during the Unit 1 residual heat removal system surveillance for Unit 2 operability.
The contaminated area inside the Unit 1 drywell access contained an excessive amount of miscellaneous materials (Section 01.2).
During observation of routine operational activities, the inspectors observed good procedural compliance.
Self checking and communications were conducted in accordance with licensee management'expectations..
A deficiency involving nitrogen gas bottle storage in the reactor building was corrected promptly by the licensee.
Good supervision of a reactor operator trainee was noted during operation of a diesel generator (Section 01.3).
The Operators displayed an excellent questioning attitude with identification of a residual heat removal service water testing issue.
Operator questioning ensured that a pump/valve interlock was appropriately tested (Section 04. 1).
Personnel errors during development and review of a clearance for maintenance work on a reactor protection system power supply resulted in an inadvertent engineered safety features actuation (Non-Cited Violation 260/98-03-01.
Clearance Deficiency Caused ESF Actuation, Section 08.4).
~
Maintenance Testing of the Standby Gas Treatment relative humidity heater flow switches was well controlled and conducted in accordance with procedures.
Second party checking and communication practices were good.
Some inconsistencies were noted involving the testing methodology and measurement of air flowrates.
An apparent discrepancy between TS requirements and the test procedure was identified by the licensee.
An unresolved item was opened to address addition'al review (URI 260.296/98-03-02 Standby Gas Treatment System Flow Switch Testing Issues, Section Ml.1).
The licensee identified that testing of,a control room emergency ventilation system damper did not fully implement Technical Specification (TS)
requirements.
The problem was identified during reviews for Generic Letter 96-01. Testing of Safety-Related Logic Circuits (NCV 260.296/98-03-06, CREV Damper Not Fully Tested, Section ES. 1).
Implementation of GL 89-10 remained partly incomplete.
as the licensee had not satisfactorily obtained and/or analyzed motor-operated valve (MOV) test data to support certain assumptions (Section El. 1).
Plant Su ort Radioactive material was labeled appropriately.
and areas were properly posted.
Personnel dosimetry devices were appropriately worn.
Radiation work
'activities were appropriately planned.
Radiation worker doses were being maintained well below regulatory limits.
Contamination control, although challenging was effective.
Reduction in the generation of radwaste demonstrated aggressive management (Section Rl. 1).
The licensee had effectively implemented a program for shipping, receiving and response to emergencies involving radioactive material shipments as required by NRC and DOT regulations (Section R1.2).
The water chemistry control program met the regulatory requirements and the licensee was using depleted zinc oxide to help lower general and'omponent radiation dose levels (Section R1.3).
A non-cited violation for failure to meet NRC requirements in 10 CFR 50 Appendix B Criterion III Design Control was identified.
Discussions with cognizant licensee personnel and a review of performance records determined the percentage unavailability of the Radcon continuous air monitors was an area that could be improved.
The licensee was conducting thorough formal RP and chemistry audits as required by Technical Specifications and conducting self-assessments.
The licensee was developing corrective action plans.
trending, and completing corrective actions in a timely manner (Non-Cited Violation 50-296/98-03-07, Incorrect Pretreatment Radiation Monitor Alarm Setpoints.
Section R2.1).
~Securit The inspector determined that the licensee had procedurally established a
process to ensure that personnel who were granted unescorted access were trustworthy. reliable.
and do not constitute an unreasonable risk to the health ahd safety of the public (Section S1.2).
Re or t Oetails Summar of Plant Status Unit 1 remained in a long-term lay-up condition with the reactor defueled.
Unit. 2 operated at or near full power with the exception of routine and scheduled maintenance downpowers.
Unit 3 completed a mid-cycle outage to replace leaking fuel assemblies and went critical on Apri 1 18.
1998.
Following power escalation.
Unit 3 continued to operate at or near full power with the exception of routine testing and scheduled maintenance downpowers.
On Hay 10, 1998. in response to an inadvertent low,pressure feedwater heater isolation, the operators reduced power to 90K per abnormal operating instructions.
The heater isolation was caused by high heater water level due to a malfunctioning level control valve.
While performing the inspections discussed in this reports the inspectors reviewed the applicable portions of the Updated Final Safety Analysis Report (UFSAR) that related to most of the areas inspected.
Section Hl. 1 discussed discrepancies in the UFSAR description of Standby Gas Treatment System Relative Humidity Heaters.
The issue had been identified by the licensee during UFSAR reviews.
No other issues were identified.
I. 0 erations
Conduct of Operations Ol
. 1 felid l
tl t a.
Ins ection Sco e
71707 61726 The resident inspectors observed various evolutions associated with the Unit 3 midcycle outage.
Portions of the unit startup and heatup were also observed.
Observations and Findin s Prior to the start of the inspection period. Unit 3 commenced a cycle 8 midcycle refueling outage.
The outage was preplanned in the event of a reactor shutdown in order to replace leaking fuel assemblies.
The leaking fuel assemblies were suspected to be due to crud induced localized corrosion associated with high exposure fuel.
On April 7.
1998. Unit 3 manually scrammed as
'a result of a recirculation pump runback (see IR 98-02 for details).
The inspectors monitored portions, of the fuel sipping activities.
No problems were identified.
The licensee identified 21 leaking fuel assemblies during initial sipping activities.
The licensee replaced 59 fuel assemblies in all.
These included the 21 originally identified leaking assemblies.
12 symmetrical fuel assemblies of similar exposure.
and 26 that were not sipped due to their position
in the core.
Fuel movement commenced on April 15.
1998.
One of the resident inspectors verified that the licensee had properly implemented fuel handling prerequisites.
On April 18 '998. Unit 3 commenced a reactor startup and heatup.
A resident inspector observed the rod pull and approach to criticality and portions of the plant heatup.
Strong reactivity controls were administered during control rod manipulations.
Communications and coordination of the startup were also observed to be good.
Conclusions The Unit 3 midcycle outage successfully identified leaking fuel assemblies.
Strong reactivity controls were administered for control rod manipulations during the subsequent startup.
01.2 'nit
RHR Surveillance a.
Ins ection Sco e
71707 61726 A resident inspector observed performance of 1-SI-4.5.B.11.
"RHR Unit 1 X-Tie for Unit 2 Operability."
This surveillance demonstrates that the adjacent Unit 1 cross-tie RHR pumps'eat exchanger.
and motor operated valves are operable to support RHR Unit 2 operability requirements (TS 3.5.B. 11).
Observations and Findin s On Hay 7.
1998, a resident inspector observed performance of 1-SI-4.5.B. 11,
"RHR Unit 1 X-Tie for Unit 2 Operability."
The inspector attended the prejob brief.
The brief was attended by all personnel involved with the performance of the survei llance.
The brief contained a good discussion of the overview of the surveillance, stressed the use of clear communications and maintaining the Unit 1 operator informed of procedure steps completed.
The inspector accompanied the two Assistant Unit Operators (AUOs)
that performed system venting.
The AUOs used good communications and self checking techniques during manipulation of system valves.
The inspector identified a minor deficiency in the installation of the temporary pressure gage used to measure suction pressure on the
RHR pump.
The gage was supposed to be mounted at the same elevation as the normal pressure indicator.
However. the temporary gage was mounted approximately one foot below the normal pressure indicator.
Instrument mechanics subsequently corrected the deficiency.
The inspector determined that the deficiency would not have effected the acceptance criteria of the surveillance.
Also while observing system venting'he inspector noted an excessive amount of materials (e.g., scaffolding material, flashlights.
anticontamination clothing not in the prescribed bins, etc.) in and around a contaminated zone in the Unit 1 drywell access enclosure.
N
01.3 a.
The licensee previously identified this problem and was planning to remove the excess materials.
The surveillance was performed by a reactor operator -in-training.
The inspector observed that the trainee was properly supervised during the surveillance.
The operators demonstrated good self checking techniques and consistently demonstrated actions that minimized potential problems with testing performance (e.g.,
assured that all remote data was taken prior to performing the next step, reviewed data prior to commencing subsequent steps).
The inspector observed good coordination of the different crafts. participating in the evolution and with the Unit 2 operators.
Conclusions The Unit 1 operator and AUOs demonstrated good coordination, communications and self checking during the Unit 1 RHR surveillance for Unit 2 operability.
The contaminated area inside the Unit 1
'rywell access contained an excessive amount of miscellaneous materials Routine 0 erational Activities Ins ection Sco e
71707 The resident inspectors observed the performance of Operations personnel conducting routine activities.
Assistant Unit Operator rounds, emergency diesel generator testing and return to standby.
and recharging of control rod drive hydraulic accumulators were observed.
Procedural compliance and work practices were examined.
Observations and Findin s On May 20, 1998, the inspector observed the performance of the Assistant Unit Operator (AUO) outside tour on evening shift.
Tours were conducted in a professional manner.
The AUO initiated a work request for a problem that was identified with the local indication for an Emergency Equipment Cooling Water strainer backwash discharge check valve.
On May 14. during a backshift tour.
a resident inspector observed an AUO recharging two Unit 3 control rod drive hydraulic control units (HCUs).
The AUO actively referenced the procedure.
Self checking was evident during valve manipulations.
The AUO was diligent in communicating his actions with the control room operators.
The inspector observed that the AUO very slowly increased pressure when charging the first accumulator.
The relief valve on the charging rig had a Work Request dated August 17 '997, which indicated that the relief was lifting prematurely during charging evolutions.
The inspector observed a very small nitrogen leak at the charging connection cap after the AUO had completed a soap test and left the
04.1 first HCU.
The AUO immediately corrected the slow leak.
During charging of the second HCU
~ the AUO had difficulty maintaining the correct differential pressure and decided to use the other HCU charging rig to complete the task.
During movement of the rig from its storage location on the other side of the reactor building. the inspector observed that the brackets securing the high pressure nitrogen bottles were wired in place instead of being pinned.
The inspector discussed this with the AUO and subsequently the site safety representative.
The storag of other high pressure gas bottles was examined by the inspector and no other problems were ident'ified.
Later that day, the inspector verified that pins had been installed in the brackets.
On Hay 19, one of the resident inspectors observed the performance of O-SI-4.9.B(A) Diesel Generator A Operability check.
The fast start and loading of the diesel generator were conducted following routine maintenance activities.
The inspector observed that the two control room operators conducting the test had a good discussion of specific
.expectations prior to the first start.
A reactor operator trainee operated the diesel controls and was closely supervised by a licensed operator.
Self checking of switches and indicators was evident.
The reactor operator ensured that the trainee understood the, paralleling section of the procedure prior to beginning it.
Step 7. 18. 1 of O-SI-4.9.B(A) required that the diesel generator be placed in standby readiness and referred to Operating Instruction 0-OI-82, Standby Diesel Generator.
Several hours later, the inspector verified selected requirements listed in Section 4;2 of 0-OI-82 were met.
On the A diesel generator.
switch positions, pump conditions, and governor controls were verified.
The governor controls for the B.
C.
and D diesel generators were also veri fied.
Conclusions During observation of routine operational activities. the inspectors observed good procedural compliance.
Self checking and communications were conducted in accordance with licensee management expectations.
A deficiency involving nitrogen gas bottle storage was corrected promptly by the licensee in the reactor building.
Good supervision of a reactor operator trainee was noted during operation of a diesel generator.
Operator Knowledge and Performance Residual Heat Removal Service Mater Pum and Header 0 erabilit and Flow Test Ins ection Sco e
61726 On April 28, 1998, the inspector observed portions of Surveillance
.
Instruction 3-SI-4.5.C. 1(3). Residual Heat Removal Service Water (RHRSW)
Pump and Header Operability and Flow Test. Revision 11.
The
08.1 inspector focussed on the performance of the operators during the testing.
Observations and Findin s The inspector noted that the test performer was an operator trainee who was closely monitored by the responsible Licensed Reactor Operator.
In general.
good communications by the operators were noted and the Unit Supervisor (US) reinforced communication expectations.
Minor problems were identified concerning second-party verification. which was required in several steps of the procedure.
Performance of second-party verification improved following discussion with the Unit Supervisor.
During performance of the SI. the operators were required to throttle RHR heat exchanger A cooling water outlet valve to achieve an RHRSW flow of 500 gpm, then stop RHRSW pump A2 using the control room handswitch.
The operators were then required to verify that the RHR heat exchanger A cooling water outlet valve closed when the RHRSW pump is. stopped.
The operators noted that while attempting to close the valve, the flow decreased to approximately 700 gpm. then dropped immediately to approximately zero.
The pump was tripped and the operators discussed their observations with the Unit Supervisor.
During testing of'he Bl RHRSW pump, the US observed that the same situation occur red.
The system engineer was contacted and responded to the control room.
Discussions indicated that the purpose of this portion of. the testing was to confirm oper ation of the inter lock which closes the RHR heat exchanger cooling water outlet valve when the pump is stopped.
The licensee successfully reperformed parts of the testing on the Al. A2, and Bl RHRSW pumps by stopping the pumps at a flowrate slightly higher that the 500 gpm required by the procedure.
A test deficiency documented the problems and indicated that a procedure change was planned to resolve the issue.
Conclusions The Operators displayed an excellent questioning attitude with identification of residual heat removal service water testing issue.
Operator questioning ensured that a pump/valve interlock was appropriately tested.
Hiscellaneous Operations Issues (92901)
Closed Unresolved Item 260 296/97-11-03:
Adequacy of Control Room Emergency Ventilation (CREV) Standby Train Circuit Testing.
In IR 97-11
~ the resident inspectors reviewed the effect of having the SYSTEM PRIORITY SELECTOR SWITCH (0-XSW-031-7214) in the.'A'osition with the 'A'rain inoperable:
This condition was found by a resident inspector on November 19.
1997.
when the 'A'rain of CREV was taken out of service due to maintenance.
The inspectors reviewed
logic diagrams and control drawings and concluded that the 'B'rain of the CREV would have operated if called upon.
This was based on the standby feature design of the two trains.
Since the 'A'rain was selected'n initiation signal would be sent to both trains to start, however. only the preferred train would start immediately.
The non-preferred train operation would be delayed from starting for some time by a timer and flow switch arrangement.
The inspectors reviewed the licensee's fl'ow switch/time delay ci rcuitry testing requirements.
The flow switch was found to be periodically calibrated.
However, operation of the time delay relay and associated contacts had not been periodically tested for both
, tr ains.
Review of surveillance testing showed that the standby feature, via the time delay and flow switch arrangement, has not been tested when the selector switch is selected to the B train since pre-operational testing of the upgraded CREV system in 1993.
The inspectors concluded that additional review of the testing and potential effects of the standby train logic fai lures was necessary.
The licensee conducted a detailed team review of the CREV system modification that was implemented in 1993.
The review team consisted of personnel from Systems Engineering, Mechanical Design, and Electrical Design.
The team concentrated on the adequacy of system design. installation and testing.
The licensee's review concluded that the CREY system was adequately designed and tested to ensure that the system will perform its intended function.
The licensee stated that testing the standby feature was not required by current Technical Specifications (TS).
The licensee did, however, perform special testing on the CREV system on December 12, 1997.
The test demonstrated that the 'A'rain would start as the standby train when the preferred train ('B') failed to start.
The inspector verified, by reviewing CREY system control circuitry drawings'hat the method used by the test actually challenged the flow switch/time delay circuitry.
The licensee's review of failure mechanisms showed that CREV subsystems are physically and electrically separated with the exception of the selector switch that selects the preferred train.
The selector switch has metal barriers in its enclosure to provide divisional isolation.
The commonality of the selector switch was evaluated in the design change Safety Assessment/Safety Evaluation and determined to be acceptable based on the positive indication of failure provided for each division by status lights.
The inspectors reviewed the TS and NRC Generic Letter (GL) 96-01 and concluded that testing the standby feature is not currently required.
Current TS (Table 4.6.G) only requires functional testing of CREV system automatic 'actuation.
Logic system functional testing (LSFT)
is required for control room isolation logic (see Section EB. 1 LER 50-259/97002:
Inadequate CREVS Surveillance Instruction Identified During Generic Letter 96-01 Review).
The licensee considered this
logic testing only included initiation logic and actuation of the necessary equipment to isolate the control room.
The inspectors concluded that the licensee's interpretation that testing of the switch and standby circuitry was not within the scope of GL 96-01 under the current TS was reasonable.
Additionally. the licensee has implemented procedure controls to maintain the 'A'rain as the preferred start train of the CREV system unless the 'A'rain is inoperable.
This was part of the licensee's corrective action for VIO 50-260, 296/97-11-02.
Failure to Control CREV Switch Position (see Section 08.2).
The licensee determined that Improved Standard Techni.cal Specifications ( ISTS). submitted for NRC approval, will requi re testing the standby feature control circuit when either train is selected as the preferred start train.
This is because ISTS surveillance requirements specify the performance of logic system function testing on CREV system instrumentation.
The inspectors concluded that no regulatory requirements were violated.
With the switch properly controlled in the "A" positions the CREV system is maintained in a configuration which has been routinely tested.
This URI is closed.
Closed Violation 260 296/97-11-02:.Failure to Control CREV Switch Position.
This violation was or iginally discussed in IR 97-11.
The corrective actions described in the licensee's response letter.
dated January 28, 1998 'ere found to be reasonable and complete.
This included procedure controls to maintain the 'A'rain as the preferred start train of the CREV system unless the 'A'rain is inoperable.
The licensee determined that the violation resulted from an inadequate operations review of the impact of the SYSTEN PRIORITY SELECTOR SWITCH.(0-XSW-031-7214)
on operations procedures when the new CREV system was installed in 1993.
Section 08. 1 describes a
detailed licensee review of the CREV modification which specifically examined the adequacy of the safety evaluation.
The inspector verified that the corrective actions to control the system priority selector switch were properly implemented.'ther licensee corrective actions included verifying that switches and controls in other safety systems were referenced in the appropriate procedure.
On Hay 12, 1998. during CREV system maintenance.
the inspector verified the selector switch was correctly positioned.
No similar problems were identified.
This violation is closed.
Closed Violation 260/97-05-01, Failure to Reset Locked Scoop Tube.
The licensee responded to the violation in a letter dated July 1, 1997.
In addition to personnel actions
~ the licensee briefed all operating crews on the communications and performance deficiencies involved.
Operations management incorporated the incident into simulator sessions which, challenged the operating crews in making correct decisions under similar conditions.
Operations management observed the scenario.
The senior resident inspector observed one of these sessions soon after the incident and noted that the licensee's
actions were in accordance with the response.
Two Region II reactor engineers reviewed the licensee's implementation of this issue into training activities and concluded that the actions were appropriate.
(Section 05. 1 of Inspection Report 98-02)."
Section 01.3 of Inspection Report 98-02 also described good operator.actions regarding a recirculation pump runback.
including prompt initiation of a manual scram.
The violation is closed.
Closed Licensee Event Re ort LER 260/98-001-00 'ngineered Safety Feature (ESF) Actuations When the 28 Reactor Protection System Bus was Transferred to a De-energized Source Because of Inattention-to-Detail in the Preparation of a Clearance.
On Harch 8.
1998.
power was lost to reactor protection system (RPS)
bus 2B when Assistant Unit Operators placing a clearance to support work on the RPS motor generator set.
placed the normal/alternate control switch to the normal position as specified by the clearance sheet.
The licensee identified that the cause of the event was the failure of the Shift Support Tagging Unit Operator preparing the clearance to exercise proper attention to detai 1 to ensure the tagged position for the 2B RPS normal/alternate switch was listed as alternate on the clearance position sheet.
The licensee also determined that a
contributing factor was that the Shift Support Supervisor (SSS)
reviewing the clearance failed to identify that the, 28 RPS NG set was being tagged and that the normal/alternate switch position should b'
listed as alternate.
The failure of the SSS to adequately independently review the hold notice boundary as required by Site Standard Practice SSP-12.3
~
Equi pment Clearance Procedure.
Revision 22, Section 3;1.2.V. resulted in the de-energization of the 2B RPS Bus and corresponding ESF actuations.
Review of the associated problem evaluation report BFPER980346 noted identification of a previous similar event as documented in BFPER970034.
This January 6,
1997, event involved a situation where the tagout was not properly prepared by an SST and the reviewing SSS did not identify that a component was omitted from the clearance sheet.
The clearance involved nonsafety related equipment and the problem was identified by the licensee before work commenced on the system.
In the January 1997 events a component was erroneously omitted from the clearance sheet during preparation; during the recent events the component was included but the switch position was incorrect.
After detailed review of the issues.
the inspectors determined that the corrective actions for the January 1997 incident would not reasonably be expected to have prevented this incident.
The licensee's corrective actions.
which are documented in the Licensee Event Report, included personnel corrective actions and a
peer review of any clearance written by the SST UO involved in the event, prior to the SSS review of the clearance.
The PER which addressed this issue documented an additional corrective action to reemphasize, during Assistant Unit Operator requalification training.
the necessity and expectation to maintain a vigorous questioning
attitude at all times.
This corrective action is planned for completion on June 26, 1998.
The inspector concluded that the corrective actions taken and planned to correct the violation and prevent recurrence and the date when full compliance will be achieved are adequate.
This non-repetitive'icensee-identified and corrected violation is being treated as a Non-Cited Violations consistent with Section VII.B.1 of the NRC Enforcement Polic
.
This is identified as a non-cited violation 260/98-03-01.
Clearance Deficiency Caused ESF Actuation.
II. Maintenance Conduct of Maintenance Standb Gas Treatment S stem Relative Kumidit Keater Flow Switch Calibration Ins ection Sco e
61726 62707 During the period of Hay 20-Hay 22, the resident inspectors observed the performance of Surveillance Instruction (SI)
O-SI-4.2-13(A)
Standby Gas Treatment (SBGT) Train A Heater Flow Switch Calibration.
The inspectors referenced Technical Specification (TS) requirements and applicable sections of the Updated Final Safety Assessment (UFSAR) during review of the test procedure.
During the testings problems with the test methodology were identified and subsequently addressed.
Observations and Findin s The testing consisted primarily of adjusting the SBGT filter train suction damper and determining the air flowrate (in the plant stack SBGT lines) at which the relative humidity heaters de-energize.
TS Tables 3.2.A and 4.2.A require that the heater flow switches be calibrated once per year and functionally tested.
One of the inspectors observed the initial testing in the plant,stack.
The inspector noted that the prerequisites had been met and signed off and the overall testing was being coordinated by a designated Instrumentation and Control ( I&C) worker.
The revision of the SI being utilized as the controlling document was correct.
Communications were established with workers at three other plant locations involved in the testing.
Microtector Gages are used to measure air flow in both.SBGT lines.
The inspector verified that the instruments were set up in accordance with Technical Instruction O-TI-194, Hicrotector Gage Operation and the SI.
Stickers on the instruments indicated that they were within calibration.
The instrumentation had a range of 0-2.0 inches of water column.
Step 5.3.2 of the SI stated that the recommended test equipment had a range of 0-1.5 inches.
The workers indicate that the instrumentation had been approved for the testing by engineering.
The inspector observed good concurrent second party verification
I'~
during connection of the microtectors to the sensing lines.
The lead performer contacted his foreman to resolve a typographical error noted during the connection steps.
The initial measured total
"as found" flowrate was just below the acceptance criteria of 2008 cfm (cubic feet per minute).
The system engineer was contacted and promptly reported to the stack. 'fter discussion with the workers.
the steps were performed again.
Slow throttling of the damper in small increments was emphasized.
Total flow measured this time was 4280 cfm, just above the acceptance value of 3992.
The inspector noted that 0-TI-194. Hicrotector Gage Operation was not actively referenced during the measurements.
The TI is an information use procedure.
The inspector did not observe any actions which could have caused inaccurate readings.
The inspector noted that sometimes the workers did not obtain several readings and average them as described in the TI.
Step 7.3. 13 of the SI states that if the "as found" flowrate is between 2288 and 3712 cfm. the flow switches which de-energize the heaters do not require calibration.
Flow switch 0-FE-65-208 was subsequently calibrated.
Portions of that work were observed by another resident inspector, no problems were noted.
The system engineer and the inspector discussed the testing methodology regarding the relays which cause the heaters to be de-energized as flow decreases.
The SI required workers to measure the flowrates only after the second of the two relays changes state.
The engineer indicated that he would be reviewing the logic for the heaters.
TS Table 3.2.A lists the flow switches as two instrument channels per SBGT train.
Section 5.3.3.7 of the UFSAR refers to the flow switches and implies that they are "redundant"from the perspective of turning off the heaters when low flow is present.
The inspectors noted that controlled drawings indicated that the relays are in a parallel ci rcuit and that both must change state to de-energize the heaters.
The inspectors concluded that the testing may not have been adequate to fulfill TS requi rements.
Mhen engineering management was contacted, the inspectors were informed that the system engineer had identified this problem and that reviews of the issue for corrective actions were in progress.
The existing testing procedure would have identified a problem if both flow switches did not drop out at acceptable flowrates.
Additionally. if the switches did not actuate within flowrates specified in the procedure.
they were calibrated.
After review of previous testing data, the licensee determined that the previous testing of the B SBGT had not addressed both flow switches adequately.
The operability of the other train flow switches was supported by previous testing.
A 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TS Limiting Condition for Operation (LCO) was entered regarding the testing.
The SI was subsequently revised to require measurement of flowrate when each relay dropped 'out.
Late on Hay 21 '
'i
testing of the B SBGT train flow switches was performed.
One of the resident inspectors observed some of this testing.
During initial
"as found" testing
~ both relays dropped out at flowrates within the procedural limits.
The testing required performance of "as left" measurements (this section of the SI also verified annunciator operation).
The "as left" measured air flowrate was too high at the oint that one of the relays dropped out and 'the flow switch had to e calibrated.
At 5:35 a.m.
on May 22. testing of the 8 SBGT train was completed satisfactorily and the LCO was exited.
Problem Evaluation Report (PER) 98-005972-000 was initiated on May 21.
1998, to address the problems noted with the testing.
The licensee indicated to the inspectors that a Licensee Event Report will be initiated to address the apparent discrepancy between the TS requirements and the testing methodology.
During the testing, the inspector noted indications that the testing methodology needs additional review.
It was clear that very slow and controlled damper throttling is essential to accurate testing.
The accuracy of the air flowrate measurements may not be sufficient at the low flowrates.
For example.
the accuracy of the involved instrumentation is
.002 inches of water column.
The measured differential pressure at the point that the relays drop out is often very low. with typical values of.001 or.002 inches.
Since the indications are doubled before conversion to flowrates,
.001 inches of indicated water column is a significant portion of the less than 2000 cfm flowrate acceptance band.
The inspector also noted on two separate occasions that flowrates measured after the dampers were subsequently re-opened after throttling were significantly different than the expected flowrates.
Previously. there have been questions regarding effects of stack dilution fan operation on air flow in the SBGT lines.
Additional review is also necessary regarding the licensee's actions in response to Generic Letter (GL) 96-01, Testing of Safety Related Circuits.
The problem with the relative humidity heater relay testing was not identified during the review conducted for the GL.
At the end of the inspection period, it was not clear how the licensee had treated SBGT circuitry during the GL 96-01 reviews.
The licensee provided documentation to the inspectors which indicated that the difference.between the UFSAR description and the functioning of the heater relays had previously been identified.
Inaccuracies with the description of the relative humidity heater functioning were identified during the performance of Technical Instruction O-TI-353.
UFSAR Functional Review Criteria in October 1996 and the UFSAR will
. be revised.
The licensee identified the discrepancy between the TS and the testing procedure and took prompt corrective actions.
Additional review of the testing methodology is necessary to ensure that regulatory requirements are met.
The licensee has initiated PERs 98-'05972-000 and 98-005696-000 to address the testing problems and potential issues with operation of the stack dilution fans.
This
Ml.2
issue is identified as Unresolved Item Z60.296/98-03-02.
Standby Gas Treatment System Flow Switch Testing Issues.
The issue is unresolved pending additional review of S8GT air flowrate measurements and GL 96-01 actions.
Conclusions Testing of the Standby Gas Treatment relative humidity heater flow switches was well controlled and conducted in accordance with procedures.
Second party checking and communication practices were good.
Some inconsistencies were noted involving the testing methodology and measurement of air flowrates.
An apparent discrepancy between TS requirements and the test procedure was identified by the licensee.
An unresolved item was opened to address additional review.
Maintenance Activit Observations a.
Ins ection Sco e
6Z707 617Z6 The inspectors observed portions of the following work activities:
2-SI-4.1.8-16(A)
WO 97-011575-000 2A Observations and Findin s RPS Ci rcuit Protector Cal ibrati on/FT for 2A1 and 2A2 Standby Liquid Control Pump/Gear Reducer PN M8.1 While observing 2-SI-4.1.8-16(A).
RPS Circuit Protector Calibration/FT for 2Al and 2A2, the inspector noted that the technicians were sensitive to the typographical discrepancies in the procedures and appropriately addressed the discrepancies.
The inspector verified that the new oil stock item numbers used in conjunction with WO 97-011575-000 for oil change of the pump and gear reducer were acceptable.
Overall performance of the maintenance work was good.
Miscellaneous Maintenance Issues (62707, 92902)
Closed Licensee Fvent Re ort LER 296/97-002-00, Unit 3 High Pressure Coolant Injection (HPCI)
System Unexpectedly Isolated Resulting in an Engineered Safety Features (ESF) by the Actuation of the Isolation Logic.
This issue involved a personnel error in that a
voltmeter was connected to the incorrect pressure switch during testing.
Inspection review of this incident is described in Section N1.4 of Inspection Report 97-05.
The incident was cited as one of the examples in Violation 260,296/97-05-02, Failure to Implement Maintenance Procedures.
Additional review of the voltmeter issues associated with the incident will be performed for closure of the violation.
Since this incident. there has not been significant
examples of similar deficiencies involving Instrumentation and Control workers.
The LER is closed.
III. En ineerin E1. 1 Im lementation of Generic Letter GL 89-10 "Safet -Related Hotor-0 crated Valve Testin and Surveillance" Ins ection Sco e Tem orar Instruction 2515/109 This inspection evaluated the licensee',s completion of GL 89-10.
It concentrated on the actions which the licensee had undertaken to address issues identified during Inspection 50-260.
296/97-11.
These actions were to involve:
~
Preparation of test-based justi.fications for the valve factor,
'stem friction coefficient.
and rate of loading'ssumed in the design calculations for each GL 89-10 MOV.
~
Updating of calculations and HOV setting drawings based on the justified assumptions.
~
Implementation of trend reporting based on the periodic reviews recommended by GL 89-10.
~
Correction of procedures that did not implement the licensee's commitment to assure that applicable systems or-trains for certain MOVs would be declared inoperable when the MOVs were placed in their non-safety positions.
Ouring the course of the inspection, portions of several setup calculations were reviewed.
In addition, the inspectors conducted a
detailed review of the calculations for the following HOVs.
~
HOV 3-FCV-73-03 Migh Pressure Coolant Injection Steam Supply Isolation Valve HOV 3-FCV-75-22 Core Spray Loop 1 Test Valve
~
HOV 3-FCV-73-35 High Pressure Coolant Injection Test Return Valve
~
HOV 3-FCV-71-02
~
HOV 3-FCV-69-01 Reactor Core Isolation Cooling Steam Supply Inboard Isolation Valve Reactor Water Cleanup Suction Inboard Isolation Valve
~
MOY 3-FCV-74-57 Suppression Pool Spray Test Isolation Valve
Observations and Findin s
'4 1.
Justifications for Assum tions Valve Factors Calculation MD-Q0999-980001. revision 2.
"MOV Calculation Input Parameters."
specified Browns Ferry's valve groups and the related valve factor justifications.
Gate valves were divided into 15 groups/subgroups and globe valves were divided into 7 groups.
The inspectors reviewed this calculation and found that the valve factors assumed for some groups were riot based on applicable test results, as intended by 'GL 89-10.
The following concerns were identified:
~
The disc and seat, ring surfaces of gate valve groups 3b and 7 had Stellite 21 and Deloro hardfacing.
The licensee assumed a valve factor of 0.55 for these valve groups but did not have test data from valves with the Satellite 21 and Deloro hardfacing to justify this valve factor.
Instead, the licensee relied on test results from valves with Satellite 6 surfaces and limited evidence that this materi'al had similar friction characteristics to Satellite
and Deloro.
The inspectors found that this did not meet the intent of GL 89-10, because valve performance should be established through design-basis tests of identical or similarly designed valves.
, The inspectors noted that the licensee's documentation did not indicate that the industry had been broadly surveyed to determine if test data had been or was being developed on valves with Satellite 21 and Deloro hardfacings.
The inspectors were informed that tests on valves with these surfaces were to be performed in the nuclear utility Joint Owners'roup (JOG)
MOV periodic verification program.
The licensee is a participant in this JOG.
~
The test data which the licensee used to justify the 0.60 valve factor selected for gate valve groups lla and lib was not clearly applicable.
The test data came from valves that differed significantly in design from the valves in groups lla and lib: the test conditions under which some of the data was obtained was not identified. or differed significantly from the design-basis conditions of the valves in groups lla and 11b:
and there was no documented consideration of the variability of some of the test data.
The inspectors found that the licensee's documentation did not indicate that a broad survey of the industry had been performed to determine if test data that was more clearly applicable to the
.
group lla and 11b valves had been or was being developed.
~
The valve factor justifications f'r globe valves for Group 2 (10-inch Crane)
and Group 3 (2-inch Hancock) were not justified by test data from similar valves.
A valve factor of 1.20 was applied
pl
~ ',l tl f'
to these valves.
As in the case of the gate valve groups referred to in the previous paragraphs.
the licensee's documentation did not indicate that a broad survey of the industry had been performed to determine if'est data applicable to these valves was already available in the industry.
Stem Friction Coefficients Inspection 97-11 noted that the licensee had not documented an evaluation of in-plant stem friction coefficient data to justify the use of the 0. 15 stem friction coefficient selected for calculations.
The licensee subsequently reviewed available static and dynamic test data and found that a value of 0. 158 bounded the static testing and 0. 188 bounded the dynamic testing.
based on a 97.5X confidence level statistical analysis.
Calculation MD-Q0999-980001 specified that a
stem friction coefficient of 0. 15 would be used if a rate of loading margin of 18K was applied.
Otherwise, a stem friction coefficient of 0.20 would be used.
The inspectors found the licensee's approach for establishment of'tem friction coefficients to be consistent with the test data.
During Inspection 97-11
~ due to the licensee changing stem lubricants the inspectors were concerned that any use of different lubricants and/or mixed lubricants be accounted for in the licensee's justification of stem friction coefficients and rate of loading values.
During the current inspection.
the inspectors found that Browns Ferry had changed from Never-Seize to a Mobil EP stem
'ubricant ear ly in the facility's GL 89-10 MOV program.
An effort was made to completely remove the old grease as new grease was applied.
However, some limited amount of the old grease remained.
All of the available stem friction coefficient and rate of loading data used by the program justifications reflected individual valve performance after transition to the new grease.
Based on their review of this data.
the inspectors found that the amounts of old grease present did not cause adverse valve performance and was adequately accounted for in the design stem friction coefficients and rate of loading values established by the licensee.
The inspectors considered the concern regarding use of different or mixed greases
.
resolved.
Rate of Loadin Inspection 97-11 found that the licensee had not documented an evaluation of in-plant test data to justify the 10K rate of loading
.
margin that was used in the setup calculations.
The licensee subsequently evaluated all available in-plant data and found that an 18K bias margin was required to adequately bound the rate of loading performance observed at Browns Ferry on both gate and globe valve groups.
The inspectors noted that this margin was included in the setup margins for the close and open directions and found it adequate except for two valves.
These valves (2-FCV-73-02 and 3-FCV-73-02)
had roller 'screw stem nuts that were apparently unique in nuclear
plant valve application.
The licensee was unable to obtain any in-plant or industry test data in establishing rate of loading values for these valves.
A 10K margin for rate of loading had been used in the associated valve setup calculations.
The inspectors noted that testing of HOVs with ball screw stem nuts was in progress at another nuclear facility.
While the roller and ball screw stem nut designs differ somewhat.
both designs rely on rolling friction rather than the sliding friction design in typical MOV stem nuts.
The ball screw results would provide the best available information for evaluating and justifying the rate of loading values assumed for Browns Ferry's valves with roller screw stem nuts.
Actuator Efficienc Inspection 97-11 found that the licensee assumed a run efficiency in the closing direction when predicting the torque output capability of its actuators.
Based on NRC and other test results.
the actuator manufacturer was expected to release new guidelines that address the acceptability of using run efficiencies.
In the current inspection.
the inspectors found that the licensee personnel had revised all of the Unit 3 setup calculations to use a the more conservative pullout efficiency and an application factor of 0.9.
Use of these factors is expected to be consistent with the new guidance.
Unit 2 calculations were currently being revised to implement the new factors.
2.
U datin of Calculations Inspection 97-11 identified several concerns regarding Browns Ferry's design-basis calculations and supporting program documents.
Some of these concerns had been previously identif'ied by a licensee's self-assessment and were documented in Problem Evaluation Report (PER)
971770.
The inspectors reviewed the licensee's corrective actions during the current, inspection to determine if they resolved the concerns.
The concerns and the inspectors'indings were as follows:
~
Appendix E of procedure MMDP-5 provided guidance to be used when extrapolating dynamic test data.
Inspection 97-11 identified a concern that this guidance did not include information needed to verify that the MOV test conditions were adequate to provide sufficient contact stress loads to assure reliable test results.'he licensee committed to include this information in its design standards by Jan 30, 1998.
and to revise MMDP-5 by May 30.
1998.
During the current inspections HMDP-5 was still in a revision; however.
the inspectors verified that Mechanical Design Standard DS-H18.2.21 incorporated the necessary extrapolation guidance.
Licensee personnel stated that existing dynamic test conditions had been evaluated using the new guidance and provided copies of the results.
The concern was resolved.
~
Inspection 97-11 identified a concern that the licensee had not performed a documented evaluation of testing results to verify the adequacy of valve factors and other program assumptions.
The
licensee committed to resolve this concern by January 30 '998.
During the current inspection, the inspectors reviewed the documents which the licensee had prepared to address this concern.
These documents included calculation MD-00999-980001, analysis GEN-MEB-MOV-001. and Browns Ferry's
"Engineering Report on Differential Pressure Testing of Motor Operated Gate Valves".
The inspectors found that these documents provided the previously missing evaluation and, except for the valve factor justification and roller-screw stem nut concerns identified in previous paragraphs of this report. the inspectors found the evaluations satisfactory.
~
Inspection 97-11 identified a concern that the licensee's MOV setup calculations were out, of date.
The licensee committed to revise the Unit 3 calculations by April 30.
1998.
and the Unit 2 calculations by August 31.
1998.
Revisions to the setup calculations included design-basis differential pressure changes made to implement the planned reactor power uprate modification.
The inspectors reviewed the setup calculations for six Unit 3 MOVs and verified that these calculations contained the current program assumptions for valve factor. rate of loading, stem friction coefficients and actuator efficiencies.
Differential pressures were also reviewed to ensure that the new reactor power uprate values were used.
All Unit 3 calculations used the correct rogram values.,
Correction of the Unit 2 calculations remained to e completed in accordance with the schedule committed to by the licensee.
3.
U datin of MOV Settin Drawin s Inspection 97-11 found that the controlled drawings used to establish MOV switch settings were out of date because the setup calculations had not been revised to include the results of in-plant testing.
The licensee committed to issue design change notices (DCNs) to update the switch setting sheets once the setup calculations were revised.
The inspectors reviewed DCNs for six Unit 3 MOYs and compared the settings identified in the DCNs with the settings contained in the related thrust calculations and verified agreement.
The DCNs also implemented the revised Unit 3 reactor power uprate differential pressure values.
The inspectors considered this, issue resolved for Unit 3.
4.
Im lementation of Trend Re ortin Inspection 97-11 found that procedures specified periodic review of MOV data and issuance of a trend report immediately following each refueling outage to implement a
GL 89-10 recommendation.
However, no trend report had been issued (VIO 50-260.
296/97-11-06, see Section E8 below) following the last two outages.
The licensee's response to this procedural violation was provided in a letter dated January 28.
1998.
It stated that the required trend reports had subsequently been issued and that the responsibilities for the report currently in
procedure HMDP-5 would assure future compliance.
The inspectors obtained and reviewed copies of the trend reports.
The inspectors found that the reports met the recommendations of GL 89-10.
5.
Correction of Procedures In a letter dated January 6,
1997 'he licensee provided a response to NRC concerns regarding MOVs removed from, or not included in, the scope of the Browns Ferry GL 89-10 program.
The response included a
commitment to revise the plant procedures for 18 specified valves to declare the applicable system or train inoperable when any of these valves was changed from its normal (i.e.. safety) position for testing.
Inspection 97-11 found that the procedures for all of the.
18 valves had not been revised as stated in the licensee's letter and identified this as a deviation (DEV 50-260.. 296/97-11-04, see Section E8 below).
The licensee's response to the deviation was provided in a letter dated January 28, 1998.
It indicated that the commitment to revise the procedures had subsequently been completed.
During the current inspection.
the inspectors reviewed the surveillance procedures for testing each of the 18 valves and verified that the necessary revisions had been incorporated.
This resolved the only outstanding issue regarding the scope of valves in the Browns Ferry GL 89-10 program.
In reviewing the above surveillance procedures, the inspectors questioned the terminology applied to stroke time test acceptance ranges given in the procedures.
The ranges were based on requirements specified in the applicable test standard, ON-10
"Operations and Maintenance Standards.
Part 10 '988 addenda."
The licensee's surveillance procedures referred to these limits as
"normal stroke times,"
while OM-10 did not apply a term to the ranges.
The inspectors noted that stroke times within the ranges could be abnormal, and that OM-10 required evaluation of any abnormal action.
For example, if an HOV with a refere'nce stroke time of 100 seconds stroked in 90 seconds during a test the test measurement would be within the licensee's
"normal" range (85 to 115 seconds)
but such a large reduction in stroke would actually be abnormal and should be promptly evaluated.
Responsible licensee personnel showed the inspectors that the stroke times were being plotted and assured the inspectors that any abnormal stroke time would be recognized and addressed.
While this reduced the inspectors'oncern,,the inspectors informed licensee management that they still considered the terminology inappropriate.
6.
Other Issues DC HOV Stroke Times The inspectors questioned whether the licensee had evaluated the performance of dc MOVs to assure that stroke time requirements would
be met under worst case design basis conditions.
Loads and degraded voltage reduce stroke time.'he inspectors were informed that there
had been no analysis of dc HOV stroke times.
Subsequently.
the licensee prepared an analysis.
The inspectors reviewed the analysis and found that it determined that the stroke times of Browns Ferry dc HOVs were satisfactory.
The inspectors found the analysis insufficient.
as it was based solely on qualitative arguments.
The
'nalysis did not determine actual stroke times.
Review of Previous D namic Testin Licensee personnel had to review all in-plant dynamic test data to develop the justifications for valve factors and other parameters that were used as input for setup calculations.
Instead, of just compiling data from the original test reports.
the licensee performed a comprehensive review of each dynamic test.
This review included an examination of each diagnostic trace to verify that it was zeroed properly and to ensure that the correct thrust and torque values were selected.
The review was documented in the Browns Ferry "Engineering Report on Differential Pressure Testing of Motor Operated Gate Valves".
New test reconciliation data sheets were developed in accordance with Revision 9 of Mechanical Design Standard DS-M18.2.21.
The inspectors found that the review ensured that the dynamic testing was analyzed using the latest techniques.
The inspectors considered Browns Ferry's review of previous dynamic testing to be a positive aspect of its MOV program.
Conclusions The licensee's implementation of GL 89-10 remained partly incomplete.
The licensee had not satisfactorily obtained and/or analyzed MOV test data to support the following assumptions for its HOVs:
~
Assumption of a 0.55 valve factor in calculating the design basis thrust requirements for gate valve groups 3b and
~
Assumption of,a 0.60 valve factor in calculating the design basis thrust requirements for gate valve groups lla and lib
~
Assumption of a 1.2 valve factor in calculating the design basis thrust requirements for globe valve groups 2 and
~
Assumption of a 10K rate of loading in calculating design basis thrust requirements for HOVs with roller screw stem nuts
~
Satisfactory dc HOV stroke times under design basis conditions The licensee is being requested to submit a summary of its plans and schedule to obtain test data which supports the assumed valve factor and rate of loading values, referred to in the above listing.
Subsequent NRC verification is identified as IFI 50-260, 296/98-03-03 'ustification of Valve Factor and Rate of Loading Assumptions.
The licensee was being requested to submit its plans and schedule to complete a quantitative analysis of the adequacy of the stroke times of its dc MOVs under design basis conditions.
This analysis must
E8 E8.1 E8.2 E8.3
apply the design basis loadings established in the GL 89-10 program.
Subsequent NRC verification of the analysis is identified as IFI 50-260. 296/98-03;04.
Analysis of-dc HOV Stroke Times Based on GL 89-10 Test Data.
The licensee had not completed revision of calculations and setting drawings for Unit 2 HOVs.
In accordance with its commitment to the NRC, this is scheduled to be accomplished by August 31 '998.
NRC verification of the completion of these actions is identified as IFI 50-260/98-03-05.
Revision of Calculations and Setting Drawings for Unit 2 HOVs.
Hiscellaneous Engineering Issues (92903)
Closed Violation VIO 50-260 296/97-11-06:
Failure to prepare the trend report required by procedures:
The inspectors verified the corrective actions described in the licensee's response letter, dated January 28, 1998. to be reasonable and complete.
No similar problems were identified.
Closed Deviation DEV 260 296/97-11-04:
Inadequate procedural controls for MOV activities:
The inspectors verified the corrective actions described in the licensee's response letter.
dated January 28 '998. to be reasonable and complete.
No similar problems were identified.
Closed LER 259/97-002-00:
Inadequate CREVS Surveillance Instruction Identified During Generic Letter. 96-01 Review.
On March 14,. 1997.
licensee review of surveillance instructions requested by NRC Generic Letter 96-01,
"Testing of Safety-Related Logic Circuits'
" determined that O-SI-4.2.G-2,
"Control Room Isolation and Pressurization Functional Test
" did not fully test all relay logic combinations..
The test performed did not verify proper closure of control room isolation dampers by observing actual damper movement for all logic system trips.
Damper closure was verified during radiation monitor trip testing and during the Division I Primary Containment Isolation System (PCIS)
trip testing.
However, f'r the Division II portion of PCIS testing, the surveillance verified the logic trip by observing a system initiation indicator light in parallel with the solenoid valve.
For this case, physical verification of damper operation was not observed.
The licensee promptly revised the procedure and satisfactorily tested the Division II portion of control room isolation logic by observing control room isolation damper closure.
The licensee determined that the procedure deficiency had originated in 1993 following a modification to the CREV system.
Section 08. 1 of this report describes additional licensee review of the CREV modification.
This modification included changes to the control room isolation logic system.
This non-repetitive licensee-identified and corrected
e
E8.4 Rl Rl.l
violation is being treated as a Non-Cited Violation(NCV). consistent with Section VII.B.I of the NRC Enforcement Polic
.
Resident inspector review of the LER did not identify any additional issues.
This issue is identified as NCV 260. 296/98-03-06, CREV Damper Not Fully Tested.
This LER is closed.
Closed Ins ection Followu Item IFI 260/96-10-05, High Reactor Water Cleanup (RWCU)
Pump Motor Amperage Conditions.
This IFI was opened following initial NRC review of the licensee's actions to address numerous Unit 2 RWCU pump trips due to high amperage.
The RWCU pumps were drawing more current than expected for the flowrates present in the system.
The inspector reviewed the RWCU System Status Reports and discussed the issue with the system engineer.
After detailed investigation of the problem by a special team, the licensee resolved the problem by chemically cleaning the Unit 2 RWCU pumps and associated piping in September 1997.
In addition to significantly reducing radiation levels on the pumps, the cleaning apparently removed a previously undetected film from the pump casing and impeller. resulting in pump amps returning to normal.
Additionally.
zinc injection was implemented on Unit 2 which should reduce deposits on reactor system internals.
Modifications were completed on the Unit 2 RWCU system which installed orifices to ensure that the pumps will not be placed in runout conditions.
The same modification is planned for the next Unit 3 refueling outage.
Discussions with the system engineer indicated that the licensee is continuing to monitor the pumps.
This IFI is closed.
IV. Plant Su ort Radiological Protection and Chemistry (RP8C) Controls Im lementation of Radiation Protection Pro ram Ins ection Sco e
71750 The inspectors reviewed implementation of selected elements of the licensee's radiation protection program.
The review included observation of radiological protection activities including personnel monitoring'adiological postings, high radiation area controls'nd verification of posted radiation dose rates, contamination controls within the radiologically controlled area (RCA). and container labeling.
In addition ALARA work planning. pre-job worker briefings.
and job execution observations were performed.
The inspectors also reviewed licensee records of personnel radiation exposure and discussed ALARA program details, implementation and goals.
Requirements for these areas were specified in 10 CFR 20 and Technical Specifications.
b.
Observations and Findin s The inspectors toured the health physics facilities, truck bay, reactor building. including the refueling floor. turbine building,
outside radioactive material storage areas.
radwaste processing area and the Unit 3 drywell health physics control point.
Records reviewed determined the licensee was tracking and trending personnel contamination events (PCEs).
The licensee had tracked approximately
PCEs for the 1998 fiscal year to date which included skin and clothing contaminations.
Fiscal Year FY 1995 1996 1997 PCEs 210 124 105 Radiologically controlled areas including radioactive material storage areas (RHSAs). High Rad Areas.
and Locked High Rad Areas were appropriately posted and radioactive material was appropriately stored and labeled.
The inspectors reviewed operational and administrative controls for entering the RCA and performing work.
These controls included the use of radiation work permits (RWPs) to be reviewed and understood by workers prior to entering the RCA.
The inspectors reviewed selected RWPs for adequacy of the radiation protection requirements based on work scope.
location, and conditions.
For the RWPs reviewed, the inspectors noted that approp'riate protective clothing.
and dosimetry were required.
During tours of the plant, the inspectors observed the adherence of plant workers to the RWP requirements.
The inspectors observed personal dosimetry was being worn in the appropriate location.
The inspectors discussed ALARA goals 'and annual exposures with licensee management and determined the organizational structure and responsibilities for the ALARA staff were clearly defined in organizational charts.
The inspectors took independent smears to verify contamination control in the Reactor Building, Drywell control point. Turbine
'uilding, Radwaste processing area, radioactive material storage areas'torage areas, and on the refueling floor.
All smears were counted and determined to be "acceptable."
The inspectors also independently walked posted control boundaries with a survey meter on the refueling floor.
storage areas, and tank storage areas and determined that the radiation levels were all as stated on the most recent survey.
The inspectors observed workers proper ly using friskers at the exit location from the controlled areas.
The inspectors observed workers properly exiting the protected area through of the exit portals at the East and West monitors.
The inspectors reviewed the active "Hot Spot" log as of April 14, 1998.
and
~ at the time of the inspection.
there were 41 labeled
active-HOT SPOTS" being tracked.
The inspectors reviewed the -Hot Spot" removal efforts.
In 1997. four "HOT SPOTS" were eliminated and twelve additional
"HOT SPOTS" were identified and added to the program.
Seven
"HOT SPOTS" were deemed inaccessible or infrequently accessed.
The
"HOT SPOT tracking program ensured that the locations were periodically surveyed, tracked and evaluated for shielding'lushing or component removal.
The inspector after reviewing a
selected sample of the log entries determined that the licensee maintained an aggressive
"HOT SPOT." identification. tracking and removal program.
The inspectors reviewed the use of Contamination Containment Devices, by a records (log) review and selectively observed the devices at their locations during tours of the plant.
At the time of the inspection there were 16 contaminated catch containments and 17 non-contaminated catch containments.
The licensee maintains an active program to repair leaks and remove the containment devices.
The Fiscal Year 1998 site exposure goal was set at 450 person-rem.
At the time of the inspection, the site person-rem was about 320 person-rem (TLD corrected through 12/31/97).
The Unit 3 Cycle
(U3C7)
outage dose goal was 92 person-rem with 56 person-rem actually measured.
This outage personnel dose was the lowest ever to refuel a U.S.
BWR.
The U2C9 person-rem goal was 322 person-rem with 276.7 actually measured.
The inspectors reviewed dose rate and contamination surveys for the Unit 3 outage work in the drywell and independently confirmed an internal dose assessment performed on a worker who was working in the drywell performing maintenance on a leaking sensor line.
Results of the assessment were calculated to be a small percentage of regulatory limits.
Air samples taken in the work area were reviewed and the absence of transuranic nuclides was confirmed.
The inspectors also reviewed and independently confirmed a skin dose calculation for a worker who was evaluated for a hand beta and gamma dose.
The skin dose calculation results were a small percentage of regulatory limits.
The inspectors discussed the licensee's plans to control contamination in the Unit 3 drywell during the next refueling.
Contamination smears with values as high 50 million dpm/100 cm'ere found in the vicinity of the sensor line repair.
The licensee has chartered a multi - discipline team to determine the best solution to contamination control and cleanup.
The inspectors reviewed the Contaminated Square Footage Data.
The licensee was proactive in their effort to reduce the amount of contaminated square footage throughout the plant.
In July 1997. the goal was lowered from <0.8X of the RCA. which is equivalent to 6533 square feet, to 2000 square feet.
The goal has subsequently been lowered to 1000 square feet.
At the time of the inspection the licensee was tracking 1750 square feet as contaminate IE ~
I V,
J'o II
Rl.2
The inspectors reviewed the fiscal year generation of radwaste.
The licensee implemented improvements in the liquid effluent treatment system.
The licensee has optimized the vendor supplied THERMEXR liquid treatment system and has implemented a Zero Liquid Discharge philosophy.
No liquid releases have been made since November 1997.
In November 1997 'he licensee implemented the use of waste resin liners to process the skid mounted processing system reverse osmosis brine.
The inspectors reviewed the solid radwaste shipping program.
The solid radwaste goal for fiscal year 1998 was set at 150 cubic meters (m').
The licensee had shipped approximately 50 m'hrough the end of February 1998.
In FY 1997 the goal was 320 m'ith 192.5 m'ctually shipped.
Conclusions Material was labeled appropriately, and areas were properly posted.
Personnel dosimetry devices were appropriately worn.
Radiation work activities were appropriately planned.
Radiation worker doses were being maintained well below regulatory limits.
Contamination control although challenging was effective.
Reduction in the generation of radwaste demonstrated aggressive management.
Trans ortation of Radioactive Materials Ins ection Sco e
86750 The inspectors evaluated the licensee's transportation of radioactive materials program for implementing the revised Department of Transportation (DOT) and NRC transportation regulations for shipment of radioactive materials as required by 10 CFR 71.5 and 49 CFR Parts 100 through 177.
b.
Observations and Findin s The inspectors reviewed selected procedures and determined that they adequately addressed the following:
1) assuring that the receiver has a license to receive the material being shipped; 2) assigning the form, quantity type, and proper shipping name of the material to be shipped; 3) classifying waste destined for burial; 4) selecting the type of package required:
5) assuring that the radiation and contamination limits were met:
and 6) preparing shipping papers.
The inspectors reviewed a sample of shipping papers and receipt surveys.
The inspectors determined that the shipping papers were complete and the shipping as well as the receipt surveys were complete and met regulatory requirements.
Shipment number 980301, left the site at approximatelp 12:00 noon CST on March 3, 1998.
and consisted of dewatered powdex resin contained in a high integrity container (HIC).
The inspectors called the 24-hour emergency telephone number listed on the shipping papers with a simulated
accident situation.'he Operation Duty Specialist (ODS) was familiar with the licensee shipment.
had received a faxed copy of the shipment contents and provided complete and timely answers using the Central Emergency Control Center Emergency Response Implementing Procedures (CECC EPIP 22.23) to the inspectors questions about the simulated emergency transportation event.
The inspectors also reviewed the shipping papers and surveys for shipment number 980404 that left the s'ite mid-day on April 14, 1998, and consisted of dewatered powdexR resin contained in a high integrity container.
The surveys and shipping papers were complete.
Conclusions Based on the above reviews, the inspectors determined that the licensee had effectively implemented a program for shipping.
receiving and response to emergencies involving radioactive material shipments as required by NRC and DOT regulations.
Water Chemistr Controls Ins ection Sco e
84750 The inspectors reviewed implementation of selected elements of the licensee's water chemistry control program.
The review included examination of program guidance and implementing procedures and analytical results for selected chemistry parameters.
Observations and Findin s The inspectors reviewed technical specifications (TSs) 3.6/4.6, which described the limiting conditions for operation and surveillance requirements for reactor coolant activity and chemistry.
The UFSAR indicated detailed operating specifications for the chemistry of those systems were addressed in the Station Chemistry Section.
The inspectors reviewed selected analytical results recorded for Unit 2 and Unit 3 reactor coolant taken during.the inspection period.
The selected parameters reviewed for chemistry included chloride.
conducti vity and pH.
All reviewed parameters were maintained well within chemistry limits.
The licensee had initiated injection of depleted zinc oxide (DZO) in the feed water at the beginning of U3C7 and observed significantly reduced general area radiation doses.
The inspector reviewed the licensee unit surveys to verify their observations.
Unit 2 implemented a
DZO injection; however.
the data was not yet available for review.
Conclusions Based on the above reviews't was concluded that the licensee's water chemistry control program met the regulatory requirements and
R2 R2.1
the licensee was using depleted zinc oxide to help lower general and component radiation dose levels.
Status of Radiation Protection Facilities and Equipment Process and Effluent Radiation Monitors Ins ection Sco e
84750 The inspectors reviewed selected licensee procedures and records for required surveillance on process and effluent radiation monitors and for radiation monitor availability as required by the Technical Specifications (TSs) and/or Offsite Dose Calculation Manual (ODCH).
Observations and Findin s The inspectors toured the facility to observe the physical operation of selected process and radiation monitors in use.
The inspectors reviewed selected radiation and process monitor surveillance procedures and records for performance of channel checks.
and channel operational tests.
Performance of those survei llances was required by the TSs and/or the Offsite Dose Calculation Manual to demonstrate that the instrumentation was operable.
The inspectors reviewed the most recent gaseous effluent monitors availability system status for the fourth quarter 1997 and the first quarter 1998.
The results listed overall unavailability of 3.8 and 0.04 percent for the fourth quarter 1997 and first quarter 1998 respectively.
The inspector reviewed the most recent two quarters of Radcon Area Continuous Air Monitor (Cams).
The last quarter of 1997 showed a
percentage unavailable of 18%.
Of the twenty cams on the list there were several with exceptionally high unavailability.
The top five unavailable cams on the list were:
1-3RH-90-55 (Unit 3 reactor building elevation (el.) 593)
78.3X unavailable; 2-2-RM-90-55 (Unit 2 reactor building e1.593)
78.3X unavailable; 3-1 RM-90-54(Unit
turbine building el.586)
54K. unavailable; 4-2 RM-90-59 (Unit 2 turbine building el.557)
52K unavailable:
5-0-RH-90-126 (Standby Gas Treatment building) 46.2X unavai lable.
For the most recent quarter in 1998, the total percent unavailable was 6.2 X.
The percentage unavailability of the Radcon Cams was noted as an area to be improved.
The inspectors reviewed the operations log for the Unit 3 Alarm 3-9-4C Window 27 (Off gas Average Annual Release Limit Exceeded 3-RA-90-157c).
The alarm occurred on February 12.
1998't 1710 and again six more times on that date from 1713 through 2041.
The inspectors also reviewed the actions associated with these spurious alarms.
A Problem Evaluation Report (PER)
BFPER980230 was generated as a result of the licensees investigation.
The licensee's initial investigation
subsequent to the 3-RH-90-157 "hi-hi " alarm actuation (845 mR/h)
on 2/12/98 revealed that:
1) the U2 "hi" set point value (845 mR/h) established in Technical Instruction (TI) 0-TI-15 Radioactive Gaseous Effluent En ineerin Calculations and Measurements was used for the U3 "hi-hi " alarm setting in 3-SIHI-90B. 3-ARP-94C, and in the field.
2) the U3 "hi" field set point was set to the U2 "hi-hi" value of 1690 mR/h (vs.
1065 mR/h)
~ while 3-ARP-9-4C still referred to the superseded value of 5000 mR/h, and 3) the labels on panels 2-9-10 and 3-9-10 were incorrectly labeled as "hi -hi " instead of "hi " (for which BFPER980334 was initiated).
In addition, an initial evaluation was conducted by the licensee to determine whether appropriate Radiological Emergency Plan (REP)
actions were taken due to the alarm actuation.
EPIP-1 procedure states that Emergency Action Level (EAL) 1.4-U is entered upon a
"Valid off gas pre-treatment High alarm on RA-90-157A."
Since the RA-90-157C alarm was actuated.
no EAL was entered.
Subsequent RCS and Off gas measurements taken by Chemistry indicated that samples
.
were in the expected trend. confirming the non-EAL condition.
In addition, the set point bases for the RM-90-157 alarms were reviewed by the licensee for consistency with intended function.
The existing bases limited Off gas releases to 50,000 pCi/sec and 100.000 pCi/sec (post-treatment)
for the "hi" and "hi-hi" alarms, respectively.
After review of source documents including the BFN UFSAR.
ODCH. EPIP-1.
and NUHARC, it was determined that the "hi" alarm would be more appropriately based on 100,000 yCi/sec at pre-treatment (corrected for a 30-min decay)
and the "hi-hi" alarm based on limiting the release from the stack to 0. 1 of the ODCH limit of 14.4 Ci/sec.
It was also determined that setpoint value input parameters be revised to reflect reasonably conservative data selected from operational history.
The incorrect alarm setting was identified as a violation of NRC requirements (10 CFR 50 Appendix B
III Design Control).
This non-repetitive.
licensee-identified and corrected violation is being treated as a non-cited violation (NCV),
consistent with Section VII.B.1 of the NRC Enforcement Polic
.
This is NCV 50-296/98-03-07, Incorrect Pretreatment Radiation Monitor Alarm Setpoints.
The licensee also performed an extent of condition review of other plant TI(s) associated with set points and no additional problems were identified.
Conclusions One NCV for failure to meet NRC requirements 10 CFR 50 Appendix B III Design Control was identified.
Discussions with cognizant licensee personnel and a review of performance records determined the
R7 R8 R8.1 R8.2
percentage unavailability of the Radcon Cams was an area to be improved.
Quality Assurance in Radiation Protection and Chemistry Ins ection Sco e
83750 84750 86750 Licensee quality assurance activities and self-assessment programs were reviewed to determine the adequacy of identification and corrective action programs for deficiencies in the area of Chemistry and Health Physics.
Observations and Findin s Reviews by the inspectors of Audit Report SSA 9705 dated February 26.
1998.
and the February 1998 Monthly Self-Assessment determined that quality assurance audits and self-assessment efforts in the areas of transportation and RP were accomplished by reviewing procedures'bserving work, reviewing industry documentation.
and performing plant walkdowns including surveillance of work areas by supervisors and technicians during normal work coverage.
Documentation of problems by licensee representatives were included in Quality Assurance Audits and self-assessment Reports.
Corrective actions were included in the licensee's Problem Investigative Process.
Closeouts of identified items were completed in a timely manner.
The inspectors found the nuclear assurance reports insightful. and detailed.
Identified items were trended and tracked for closeout.
A selected sample of closeout actions were determined to be timely.
Conclusions The licensee was conducting thorough formal RP and chemistry audits as required by Technical Specifications and conducting self-assessments.
The licensee was developing corrective action plans, trending, and completing corrective actions in a timely manner.
Miscellaneous RP8C Issues (92904)
Closed Ins ection Fol low-u Item IFI 50-259 260 296/97-10-05 Revise Wording to Clarify Definition of -HOT SPOT".
The inspector reviewed the reworded definition of "HOT SPOT-in Section 6. 11.2 Precautionary Posting from Procedure RCI.-1 and agreed that the
- wording was improved and that the term
"HOT SPOT" was clarified.
This item is closed..
Closed Unresolved Item URI 50-296/98-01-01:
Pretreatment Radiation Monitor Calibration Factors and Setpoint Issues.
The inspectors noted that section 9.5.6 (Inspection and Testing) of the BFN UFSAR states that
"significant changes in fuel per'formance could necessitate re-calibration of the monitors."
The UFSAR also states that
"The monitors are periodically calibrated against grab samples
~ '
if statistically significant amounts of activity are present."
In addition. the BFN UFSAR also states that "Experience has shown that the calibration of the off-gas and effluent monitors changes with isotopic content".
The licensee agreed that the wording in the UFSAR does not reflect the current methodology for sample comparisons and calibration practices.
A critical review during a Chemistry self-assessment of this UFSAR section was performed in January 1998 and BFN PER 98-0214 was written to capture the identified problems on February 12, 1998.
A tracking item (RIMS number R92980226917)
was generated to revise the wording in this section to meet the intent of current sample comparison practices used at BFN.
BFN chemistry personnel performed an evaluation of the data on the monitor response during the past Unit 3 operating cycle.
Data reflects the change expected in the transition from a core with no leaking fuel to the failed fuel condition.
Based on this review BFN personnel believe the monitors responded conservatively providing operations personnel with prompt indications of changing fuel condi.tions.
The inspectors reviewed the monitor response following the return to power operation in March 1997 through the transition into the fuel leaks over the course of the operating cycle.
The trends indicate that even with changing fuel and isotopic conditions the radiation monitor response trends with the grab sample gamma isotopic measurement.
The current methodology of grab sample comparisons showed that the radiation monitors were responding with the Unit 3 changing fuel conditions and provided operations personnel with real time information as conditions changed.
Based on discussions with other BWR's, the typical calibration for the off-gas radiation monitors of this design is to expose the detector to a high radiation source usually Cesium-137 at different radiation levels on a once per operating cycle basis.
The nuclide Cesium-137 has an energy of 0.661 million electron volts.
Re-calibration of this monitor with this source would not provide any different indication of changing isotopic mixes.
Chemistry Instruction (CI-705) was to determine the pre-treatment off-gas radiation response compared to the isotopic mix identified in the grab sample by gamma isotopic analysis.
The counting room gamma spectroscopy systems used to analyze these samples are source response checked seven days a week to NIST traceable radioactive sources of known radio-nuclides.
CI-705 uses off-gas grab sample isotopic analysis and a reactor coolant iodine analysis to monitor operating fuel performance.
During the past year the average sample frequency was once per week with Unit 3 at times as high as four times per week once changes in fuel conditions were identified.
The results from these off-gas analyses are used to quantify the concentration of off-gas present at the radiation monitoring location and provide a model of the type of predicted fuel failure including a projection of the suspected fuel fai lures..
This item is close S1 S1.2
Conduct of Security and Safeguards Activities Access Authorization X1 a.
Ins ection Sco e
81700 The inspectors verified that the licensee had an adequate procedure to ensure that individuals who were granted unescorted access were trustworthy. reliable, and did not constitute an unreasonable risk to the health and safety of the public, in accordance with the Access Authorization (AA) Program.
Observations and Findin s The inspector reviewed AA records of selected individuals to determine that the licensee had adequately implemented the AA requirements whi'ch were to ensure that individuals who were granted unescorted access were trustworthy, reliable.
and did not constitute an unreasonable risk to the health and safety of the public.
The licensee implemented
CFR 73.56, in STD-11. 1,,"Providing Access Clearance for Nuclear Plants and Safeguards Information," Revision 5, dated February 23, 1996.
Specifically, Appendix B, Evaluation Criteria for Denying, Suspending, or Revoking Clearance.
paragraph 2.0
~ states.
that TVA.may suspend or deny access to individuals who have a, "...history of mental illness or emotional instability that may cause a significant defect in the individual's judgement or reliability, or an individual whose "Psychological evaluation indicates that the individual is a risk in terms of trustworthiness or reliability."
Conclusions The. inspector determined, through AA procedures and records review.
that the licensee had procedurally established evaluation criteria for denying, suspending.
or revoking clearance, of persons with a history of mental illness or emotional instability that may cause a
significant defect in the individual's judgement or a psychological evaluation which indicates that the individual is a risk in terms of trustworthiness or reliability.
V. Mana ement Meetin s
Exit Meeting Summary The resident inspectors presented inspection findings and results to licensee management on May 29.
1998.
Additional formal meetings to discuss inspection findings were conducted on March 6 and April 17, 199 Licensee PARTIAL LIST OF PERSONS CONTACTED T. Abney, Licensing Manager J. Brazell. Site Security Manager R.
Casey.
Manager.
Access Authorization/Fitness for Duty.
R.
Coleman, Acting Radiological Control Manager J.
Corey. Radiological Controls and Chemistry Manager C. Crane. Site Vice President.
Browns Ferry R.
Greenman, Training Manager J.
Johnson, Site Quality Assurance Manager R. Jones, Assistant Plant Manager C. Kelly, Corporate Security Manager G. Little. Operations Manager R. Holi. System Engineering Manager D. Nye, Site Engineering Manager D. Olive. Operations Superintendent J.
Shaw.
Design Engineering Manager K. Singer.
Plant Manager J. Schlessel, Maintenance Manager Other A. Ladd, Authorized Nuclear Inservice Inspector INSPECTION PROCEDURES USED TI2515/109 IP 37551:
IP 62707:
IP 61726:
IP 71707:
IP 71750:
IP 81700:
IP 83750:
IP 84750:
IP 86750 IP 92901 IP 9Z902 IP 92903 IP 92904 Inspection Requirements for Generic Letter 89-10, Safety-Related Motor-Operated Valve Testing and Surveillance Onsite Engineering Maintenance Observations Surveillance Observations
'
Plant Operations Plant Support Activities Physical Security Occupational Radiation Exposure Radioactive Waste Treatment.
and Effluent and Environmental Monitoring Solid Radioactive Waste Hanagement and Transportation Of Radioactive Materials Follow-up-Plant Operations Follow-up-Maintenance Follow-up-Engineering Follow-up-Plant Support
e
~I i
ITEMS OPENED DISCUSSED AND CLOSED OPENED
~T e
Item Number Status Descri tion and Reference NCV 260/98-03-01 URI 260.296/98-03-02 Closed Open Clearance Deficiency Caused ESF Actuation (Section 08.4).
Standby Gas Treatment System Flow Switch Testing Issues (Section Hl. 1).
IFI 50-260.296/98-03-03 Open IF I 50-260. 296/98-03-04 Open Justification of Valve Factor and Rate of Loading Assumptions (Section El.l.c).
Analysis of dc MOV Stroke Times Based on GL 89-10 Test Data (Section El.l.c).
IFI 50-260/98-03-05 NCV 260 '96/98-03-06 NCV 296/98-03-07 Open Closed Closed Revision of Calculations and Setting Drawings for Unit 2 MOVs (Section El.l.c).
CREV Damper Not Fully Tested (Section E8.1).
Incorrect Pretreatment Radiation Monitor Alarm Setpoints (Section R2.1).
CLOSED T~e Item Number URI 260 '96/97-11-03 VIO 260,296/97-11-02 VIO 260/97-05-01 Closed Closed Closed Adequacy of CREV Standby Train Circuit Testing (Section 08. 1).
Failure to Control CREV Switch Position (Section 08.2).
Failure to Reset Locked Scoop Tube (Section 08.3).
Status Descri tion and Reference LER 260/98-001-00 'losed Engineered Safety Feature (ESF)
Actuations When the 28 Reactor Protection System Bus was Transferred to a De-energized Source Because of Inattention-to-Detail in the Preparation of a Clearance (Section 08.4).
LER 296/97-002-00 LER 259/97-002-00 IFI 260/96-10-05 Closed Closed Closed
Unit 3 High Pressure Coolant Injection (HPCI) System Unexpectedly Isolated Resulting in an Engineered Safety Features (ESF) by the Actuation of the Isolation Logic (Section H8.1).
Inadequate CREVS Surveillance Instruction Identi fied During Generic Letter 96-01 Review (Section E8.1)
.
High Reactor Water Cleanup (RWCU)
Pump Hotor Amperage Conditions (Section E8.2).
VIO 50-260,296/97-11-06 Closed DEV 50-260,296/97-11-04 Closed IFI 259,260,296/97-10-05 Closed Failure to Prepare the Trend Report Required by Procedures (Section E8.1).
Inadequate Procedural Controls for HOV Activities (Section E8.2).
Revise wording to clarify definition of "HOT SPOT" (Section R8. 1).
URI 296/98-01-01 Closed Pretreatment Radiation Monitor Calibration Factors and Setpoint Issues (Section R8.2).
t'